A variety of industrial as well as non-industrial applications use fuel burning boilers which typically operate to convert chemical energy into thermal energy by burning one of various types of fuels, such as coal, gas, oil, waste material, etc. An exemplary use of fuel burning boilers is in thermal power generators, wherein fuel burning furnaces generate steam from water traveling through a number of pipes and tubes within a boiler, and the generated steam is then used to operate one or more steam turbines to generate electricity. The electrical or power output of a thermal power generator is a function of the amount of heat generated in a boiler, wherein the amount of heat is directly determined by the amount of fuel consumed (e.g., burned) per hour, for example.
A typical steam generating system used in a power plant includes a boiler having a superheater section (having one or more sub-sections) in which steam is produced and is then provided to and used within a first, typically high pressure, steam turbine. To increase the efficiency of the system, the steam exiting this first steam turbine may then be reheated in a reheater section of the boiler, which may include one or more subsections, and the reheated steam is then provided to a second, typically lower pressure steam turbine. However, as is known, both the furnace/boiler section of the power system as well as the turbine section of the power system must be controlled in a coordinated manner to produce a desired amount of power.
Moreover, as is known, the steam turbines of a power plant are typically run at different operating levels at different times to produce different amounts of electricity or power based on variable energy or load demands provided to the power plant. For example, in many cases, a power plant is tied into an electrical power distribution network, sometimes called a power grid, and provides a designated amount of power to the power grid. In this case, a power grid manager or control authority typically manages the power grid to keep the voltage levels on the power grid at constant or near-constant levels (that is, within rated levels) and to provide a consistent supply of power based on the current demand for electricity (power) placed on the power grid by power consumers. Of course, the grid manager typically plans for heavier use and thus greater power requirements during certain times of the days than others, and during certain days of the week and year than others, and may run one or more optimization routines to determine the optimal amount and type of power that needs to be generated at any particular time by the various power plants connected to the grid to meet the current or expected overall power demands on the power grid.
As part of this process, the grid manager typically sends power demand requirements (also called load demand set points) to each of the power plants supplying power to the power grid, wherein the power demand requirements or load demand set points specify the amount of power that each particular power plant is to provide onto the power grid at any particular time. Of course, to effect proper control of the power grid, the grid manager may send new load demand set points for the different power plants connected to the power grid at any time, to account for expected and/or unexpected changes in power being supplied to or consumed from the power grid. For example, the grid manager may change the load demand set point for a particular power plant in response to expected or unexpected changes in the demand (which is typically higher during normal business hours and on weekdays, than at night and on weekends). Likewise, the grid manager may change the load demand set point for a particular power plant in response to an unexpected or expected reduction in the supply of power on the grid, such as that caused by one or more power units at a particular power plant failing unexpectedly or being brought off-line for normal or scheduled maintenance.
In any event, while the grid manager may provide or change the load demand set points for particular power plants at any time, the power plants themselves cannot generally increase or decrease the amount of power being supplied to the power grid instantaneously, because power generation equipment typically exhibits a significant lag in response time due to the physical characteristics of these systems. For example, to increase the power output of a steam turbine based power generation system, it is necessary to change the amount of fuel being spent within the system, to thereby increase the steam pressure or temperature of the water within the boiler of the system, all of which takes a finite and non-trivial amount of time. Thus, generally speaking, power plants can only ramp up or ramp down the amount of power being supplied to the grid at a particular rate, which is based on the specifics of the power generating equipment within the plant. Thus, when the grid manager changes the load demand set point for any particular power plant, the grid manager typically provides both a new target load demand (to be reached at some particular time in the future) and a ramp rate specifying the manner in which the load demand set point changes over the time between the current time and the particular time in the future. Generally speaking, the ramp rate indicates the manner in which the load demand set point for the power plant is to ramp up or down (change) over time between the current load demand set point and the target load demand set point.
In power plants that use a boiler to produce power, a power plant controller typically uses a feedforward controller to increase or decrease the output power in response to a change in the load demand, which may be made either locally or by a remote dispatch (e.g., by the grid manager). To change output power of the plant, the load demand set point (which may be expressed as a power demand, e.g., megawatts, or as a percentage of capacity) is typically converted to a unit load index which serves as a master feedforward demand signal for both the boiler and the turbine of each power generator unit. The boiler master demand signal then becomes the basis for producing both a master fuel control signal and a master air control signal used to control the fuel (e.g., coal) and the air flow provided to the furnace of the boiler.
Due to the sluggish nature of a boiler response however, the boiler master (or fuel master) demand is typically computed with a derivative component (i.e., a “lead” component from a frequency domain transfer function perspective), or a so-called “kicker,” which increases the response rate of the boiler, instead of using a simple linear function of the load demand index (a straight line) as the feedfoward control signal. An immediate drawback of using a derivative action as a basis for adding a lead component or a “kicker” when computing the feedforward control signal is that this derivative component risks creating a large overshoot and swing in both the unit load and the steam temperature of the boiler when the change in the load demand set point is large and/or the load demand set point ramps or ranges over a long period of time. This problem is especially prominent for a relatively fast response boilers (for example, cyclone boilers).
To solve the problem of overshoot and swing, it is known to derive the unit load index based feedforward control signal to include a derivative “kicking” action based on the difference between the current load demand set point and the final target load demand set point, such that the derivative kicking action is stronger or more prominent at the beginning of the load demand ramp (when the difference between the current load demand set point and the target load demand set point is above a preset threshold) and the derivative action weakens significantly (or is halted altogether) near the end of the ramp (i.e., when the difference between the current load demand set point and the target load demand set point is less than a preset threshold). However, this strategy has significant shortcomings in that (1) this technique loses the derivative “kicking” action when the load demand ramp range is relatively small (i.e., when the difference between a current load demand set point and the final target load demand set point is initially small to begin with) and (2) this technique has to rely on the knowledge of the final target load demand set point to determine when to remove or lessen the derivative “kicking” action within the feedforward control signal.
Unfortunately, many changes made to the load demand set point by, for example, a grid manager, are relatively small in nature and, in many cases, may not be large enough to initiate any derivative “kicking” action when a change in load demand is initially made by the grid manager (which is the time that the derivative “kicking” action is most beneficial). Additionally, in many instances, the actual final or target load demand set point value is unknown to the control system of the process plant producing the power because the remote dispatch center or grid manager only sends an incremental pulse signal to the local plant increasing the load demand set point, without informing the plant of the final target load demand to which the plant is moving. In this case, the addition of the derivative “kicking” action is difficult or impossible to apply with any certainty or effectiveness as the plant must estimate a target or final load demand set point (which may lead to over-aggressive control) or must assume that the target load demand set point is simply the next value sent by the dispatcher (which typically leads to under-aggressive control).